1. Field of the Invention
This invention relates to a method for removal of hydrogen sulfide (H2S) from H2S-containing gaseous streams utilizing a dispersed H2S scavenging agent within the stream of H2S-containing gas. More particularly, this invention is related to a method for removal of H2S from H2S-containing gaseous streams which provides a substantial improvement in surface area exposure of the H2S scavenging agent to the H2S-containing gaseous stream, thereby increasing the efficiency of H2S removal compared to conventional methods and, in turn, reducing the material requirements over conventional methods. This method is particularly suitable for H2S-containing gaseous streams, such as natural gas, containing small amounts of H2S, typically less than about 200 ppm of H2S.
2. Description of Related Art
Substantial amounts of sour natural gas are currently being produced from natural gas wells, oil wells (as associated gas), and from natural gas storage reservoirs that have been infected with H2S-producing bacteria. The presence of H2S in fuel and other gaseous streams has long been of concern for both the users and the producers of such gaseous streams. For example, in the case of natural gas, historically about 25% of the natural gas produced in the United States has been sour, that is, containing greater than about 4 ppmv H2S (5.7 mg H2S/m3). In addition to the corrosive and other adverse effects that such impurities have upon equipment and processes with which such gaseous streams interact, noxious emissions are commonly produced from combustion of the natural gas as a result of oxidation of the hydrogen sulfide. The resulting sulphur oxides are a major contributor to air pollution and may have detrimental impact upon humans, animals, and plant life. Increasingly stringent federal and state regulations have accordingly been promulgated in an effort to reduce or eliminate sulphurous emissions, and a concomitant interest exists in efficiently removing from natural gas streams and the like the hydrogen sulfide that comprises a significant precursor of the emissions.
A growing segment of the natural gas industry uses H2S scavenging processes to remove low concentrations of H2S (usually less than about 300 ppm) from sub-quality natural gas at remote locations. For this gas segment, conventional amine sweetening is not economically feasible, particularly when carbon dioxide (CO2) removal is not required. Historically, the natural gas production industry has used non-regenerable scavenging processes to treat this gas. In these processes, a scavenging agent reacts irreversibly with H2S. The reaction products are subsequently separated from the treated sweet gas and discarded.
Hydrogen sulfide scavenging agents are most commonly applied through one of the following three methods: (1) batch application of liquid scavenging agents in a sparged tower contactor; (2) batch application of solid scavenging agents in a fixed-bed contactor; or (3) continuous direct injection of liquid scavenging agents. Conventional direct-injection H2S scavenging uses an open pipeline as a contactor. In these applications, H2S scavenging agents, e.g. aqueous formulations of 1,3,5 tri-(2-hydroxyethyl)-hexahydro-S-triazine, are injected into the gas stream where H2S is absorbed into the solution and reacted to form byproducts which are subsequently removed from the natural gas stream and discarded. An alternative method for direct-injection H2S scavenging involves the forcing of a liquid jet of H2S scavenging agent through a small opening under high pressure, such as an atomizing nozzle, thereby causing the jet to break apart into small droplets. However, droplets produced by this mechanical method of atomization are generally larger than 15 microns in diameter.
For many applications, a direct-injection approach has the potential for the lowest overall costs because of its low capital cost relative to batch applications. Given the estimated $50 million per year in H2S scavenging chemical costs in the United States, significant cost savings are realizable from an H2S scavenging process utilizing continuous direct-injection of scavenging agents into the gaseous stream to be treated over conventional batch direct-injection scavenging applications.
However, studies also have been conducted which show that the performance of direct-injection scavenging systems is more difficult to predict than tower-based systems because the underlying fundamentals of direct injection are largely unknown. In addition, H2S removal results, chemical usage, and chemical costs are highly site-specific, especially with regard to gaseous fluid velocity, liquid-gas mixing conditions, and contact time.
Several problems with conventional approaches for H2S removal from H2S-containing gaseous streams continue to plague the industry. These include insufficient removal of H2S, excessive use of scavenging agents, and the requirement for excessive lengths of piping and the associated size/weight of piping contactors. Such problems are of considerable importance in offshore applications where space is very limited.